Good day and thank you for standing by. Welcome to the Capital Power third quarter 2025 analyst conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during this session, you will need to press star one one on your telephone. You will then hear an automated message advising you your hand is raised. To withdraw your question, please press star one one again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Roy Arthur. Please go ahead, sir.
Good morning, everyone. My name is Roy Arthur, Vice President, Strategy, Planning, and Investor Relations with Capital Power . Thank you for joining us today to review our third quarter 2025 results, which we published earlier today. Our third quarter report and presentation for this conference call are available on our website. During today's call, our President and CEO, Avik Dey, will provide an update on our business. Following that, Sandra Haskins, our SVP Finance and CFO, will present a review of the quarter and the financials for the company. Avik will then conclude the formal part of the presentation before we open the floor to questions from analysts in our interactive Q&A. Before we start, I would like to remind everyone that certain statements about future events made on the call are forward-looking in nature and are based on certain assumptions and analysis made by the company.
Actual results could differ materially from the company's expectations due to various risks and uncertainties associated with our business. Please refer to our cautionary statement on forward-looking information on slide three of our regulatory filings available on CDAR. In today's discussion, we will be referring to various non-GAAP financial measures and ratios also noted on slide three. These measures are not defined financial measures according to GAAP and do not have standardized meanings prescribed by GAAP and therefore are unlikely to be comparable to similar measures used in other enterprises. These measures are provided to complement the GAAP measures, which are included in the analysis of the company's results from management's perspective. Reconciliations of these non-GAAP financial measures to their nearest GAAP measures can be found in our integrated annual report.
We acknowledge that Capital Power's head office in Edmonton is located within the traditional and contemporary home of many Indigenous peoples of the Treaty Six Region and Métis homeland. We acknowledge the diverse Indigenous communities that are in these areas. Their presence continues to enrich the community and our lives as we learn more about the Indigenous history of the lands on which we live and work. With that, I will hand it over to Avik.
Thank you, Roy. Good morning, everyone, and thank you for joining us. Before I begin, I'd like to thank and recognize our people who power our strategy forward and deliver on our growth and long-term resilience each and every quarter. The success we have achieved would not be possible without their efforts. I will also take a moment to acknowledge the upcoming retirement of Sandra Haskins, whose leadership and contributions have been instrumental to Capital Power's success. I'll share a few more words about Sandra at the end of today's presentation. With that, I will now review Capital Power's third quarter results. this quarter perfectly highlights our strategy in action with execution and value creation on multiple fronts, including contracts for assets with terms to 2040 and beyond in Canada and the U.S., and more recontracting opportunities in the near term.
These efforts clearly demonstrate our ability to enhance contractedness across volume, price, and duration. This quarter, we have further strengthened our position as one of North America's leading independent power producers. Key highlights for the third quarter include advancing commercial optimization with the execution of a long-term contract with improved economics for Midland Cogeneration Venture. This extension enhances visibility of future cash flows and demonstrates our ability to unlock value for existing natural gas generation. Also, commissioning our first two Ontario battery storage projects at York and Goreway, adding 170 MW of capacity contracted through 2047. Delivered on time and under budget, these projects enhance our contractedness, portfolio diversification, and Ontario's grid reliability. With an excellent safety record after nearly 12 months of construction, these projects are a testament to our project execution capabilities.
Continued construction of three solar projects in North Carolina, all on schedule and within budget, demonstrating our commitment to enhancing our renewables platform. The successful financial integration of our newly acquired PJM assets, Hummel Station and Rolling Hills, the largest acquisition in our history. These facilities performed above expectations in their first full quarter, contributing meaningfully to Adjusted EBITDA and adding over 45 new employees and contractors to our legacy of operational expertise. Finally, we generated 13.4 TW-hours across our portfolio and completed 65% of planned outage days for the year. As we talk through our accomplishments, a consistent theme emerges of long-term lower-risk growth across our portfolio. At the core, we have this compounding growth of energy, expertise, and knowledge from the people at Capital Power. Together, these achievements reinforce our team's ability to consistently deliver, diversify our portfolio, and execute with discipline to drive long-term shareholder value.
In September 2025, we executed a new long-term contract with improved economic terms for Midland Cogeneration Venture, the largest natural gas-fired combined electric and steam generation facility in the U.S., extending the contract to 2040 and providing 10 years of incremental contracted revenue. Michigan is an attractive and growing market for electricity. This contract is an important milestone for Capital Power as it reinforces the critical role efficient natural gas assets like MCV play in maintaining grid reliability as power demand grows. Starting in June 2030, MCV will receive enhanced payments under a new PPA for 1,240 MW or approximately 75% of its capacity. This will provide long-term revenue stability and increase annual Adjusted EBITDA by roughly $100 million and an 85% increase over current contract pricing that the facility receives today. When we talk about recontracting our assets, we often talk about preserving optionality for other opportunities.
We are excited to see one of those opportunities advancing with a signed letter of intent with a leading co-location data center developer for a potential 250-MW project, highlighting how our flexible generation platform can serve new load growth reliably and efficiently. This presents an opportunity to secure superior economics from contracted capacity and build a relationship with a leading co-location data center developer. The MCV recontracting and other near-term recontracting opportunities tell a very clear story that our strategy of commercial optimization is delivering. We can extend contracts, improve economics, and secure long-term visible cash flows across core markets, all without taking on new build risk. It is a disciplined way to create value while strengthening the reliability customers depend on, and it builds on the theme of long-term lower-risk growth in years to come. This quarter, our battery energy storage projects achieve commercial operations.
We are proud to add the 120-MW York and 50-MW Goreway battery storage projects to the Ontario grid, strengthening reliability and adding a new technology to our asset base. Not only were these our first-ever battery storage projects, but they were also delivered on time, under budget, and with an excellent safety record, a testament to our team's discipline and execution. Contracted through 2047, these facilities will add approximately $35 million in annual Adjusted EBITDA over time. In addition to achieving operation of our battery storage assets, we completed 70 MW of capacity upgrades at York and Goreway with contracts to 2035. Through our various growth and recontracting efforts, this portfolio has extended its weighted average contract life from approximately five years 11 years. Together, the Ontario projects demonstrate how our expertise in gas, renewables, and storage comes together to deliver reliable, flexible power and long-term value.
Our disciplined approach is driving success across our North American platform. It's another example of long-term lower-risk growth that we believe we can continue. In their first full quarter under Capital Power ownership, the Hummel Station and Rolling Hills facilities achieved financial integration and delivered a strong Adjusted EBITDA contribution, performing ahead of expectations with higher dispatch and strong pricing. The energy price outlook in the PJM market is strong, and we continue to crystallize value for these assets using hedges with investment-grade counterparties, having put in place approximately 9 GW of hedges through 2027. We are also encouraged by continued strength in capacity pricing coming in at the cap of $329 per megawatt day for the 2026/2027 auction, approximately 20% higher than the 2025/2026 auction.
The operation optimization and integration of Hummel Station and Rolling Hills demonstrate another clear example of our disciplined growth and ability to execute, and it's reflected in the strong financial results Sandra will walk you through next.
Thank you, Avik, and good morning, everyone. Our third quarter results highlight the strength of our diversified portfolio and disciplined execution. We continue to deliver on what we said we would do: growth, stable cash flows, and a balance sheet that supports future expansion. In Q3, Adjusted EBITDA was $477 million, up approximately 20% from the same period last year. This increase was driven by strong contributions from our U.S. flexible generation portfolio following the addition of our PJM assets. The gains in the U.S. flexible generation portfolio were partially offset by lower results from La Paloma and Decatur, which were driven by generation. AFFO for the quarter was $369 million, up approximately 20% year-over-year, reflecting higher Adjusted EBITDA, current income tax recovery, and partially offset by higher finance expense.
For the nine months of 2025, Adjusted EBITDA totaled $1,166 million, 15% higher than the same period last year, driven by the same factors impacting Q3 and lower emission costs and corporate expenses. AFFO for the nine months ended September 2025 was $882 million, up 40% from the same period last year, driven by the same factors impacting Q3 and a credit for parts at La Paloma and settlement of the off-call compensation. The 2025 year-to-date financial performance positions us well to deliver strong 2025 results. To ensure portfolio reliability and better position our business to capitalize on stronger market fundamentals beyond 2026, we are updating the Alberta plant maintenance schedule. Updates to the maintenance schedule include an outage on our G3 unit in Q4 of 2025, previously planned for 2026.
This will allow G3, which is the most efficient coal-to-gas converted unit in Alberta, to be available through 2026 when we are conducting planned outages on all our other units in our Alberta portfolio. All newly installed turbines, such as those at Genesee 1 and 2, undergo an infancy period during which greater monitoring and maintenance is required to ensure long-term smooth operations. As such, G1 and G2 will have previously scheduled maintenance outages in 2026 extended but will still allow for normal operations in the interim. For Canadian flexible generation, the 2026 maintenance schedule will include approximately 40% more outage days than in 2025, with an expected capital cost of approximately $25 per kW of nameplate capacity. For our U.S. flexible generation assets, we expect sustaining capital costs of approximately $30 - $35 per kW of nameplate capacity for the same time.
While elevated compared to prior years, we believe this investment to be prudent to maximize asset life and efficiency, and we expect costs on a dollar per kW basis to decline in future years, closer to $25 per kW on average across the fleet. It is also important to note that these costs are consistent with our expectations and do not reduce our view on the return potential for our assets that we have conveyed in the past. Current Alberta forward pricing indicates that implied spark spreads for Alberta merchant capacity are projected to rise by approximately 90% between 2026 and 2028. Earlier this year, the same forwards suggested a more modest increase. The shift in expectations strengthens our conviction that 2026 is the optimal window for executing these outages.
From both operational and financial point of view, this approach best positions us to capitalize on strengthening fundamentals in Alberta beyond 2026. Despite updates to planned outages and delays on Alberta projects, we are reaffirming guidance ranges that we updated in Q2 across our key metrics. For 2025, we continue to expect Adjusted EBITDA between $1.5 billion and $1.65 billion, AFFO between $950 million and $1.1 billion, and sustaining CapEx between $215 million- $245 million. These ranges reflect strong execution year to date and confidence in our diversified portfolio's ability to deliver stable growing cash flows. With that, I'll hand it back to Avik to conclude the call.
As we reflect on the third quarter, it's clear that 2025 has been a year of delivery. We've completed all our priorities for shareholder value creation as outlined on our January guidance call, from strengthening our U.S. platform to securing enhanced long-term contracts. The story here isn't just about individual milestones, it's about the strength of the collective, the team, and the consistency. Our platform is doing exactly what we designed it to do: generate stable contracted cash flows while maintaining flexibility to capture upside in dynamic markets. That's the value of scale, diversification, and disciplined capital allocation working together. Today, Capital Power stands as one of North America's top natural gas-focused independent power producers, with a 12-GW portfolio balanced across five core markets and backed by an experienced and passionate team.
That balance allows us to manage risk, sustain growth, and fund new opportunities, all while protecting the strength of our investment-grade balance sheet. Looking ahead, the foundation we built this year positions us to meet the accelerating demand for reliable power and deliver sustained value creation for shareholders in 2026 and beyond. This morning, we announced Sandra's plan to retire from her role on December 31st, 2025. Sandra has been an integral part of our company's story, growth, and success. Since joining in 2002, Sandra has led with integrity, strategic vision, and an unwavering commitment to excellence. We're immensely grateful for her 23 years of service. Congratulations, Sandra, on your well-earned retirement. Scott Manson, our Chief Accounting Officer and Treasurer, will transition to Interim SVP Finance and CFO. A search for a new SVP Finance and CFO is underway, and a successor will be announced in due course.
Sandra will support a smooth leadership transition by remaining in an advisory role until the end of Q1 2026. Before we begin our Q&A, I'd like to remind you that we will be hosting our 2025 Investor Day event on December 9th and 10th in Toronto. Our Investor Day will provide a deeper look at how our portfolio of natural gas, renewables, and storage forms the backbone of reliability today and the foundation for growth tomorrow. We're excited to demonstrate how disciplined execution, thoughtful capital allocation, and a focus on operational excellence will continue to drive superior shareholder value, and we look forward to sharing our long-term vision and the next phase of Capital Power's growth journey with all of you in person. With that, I will hand the call back over to Roy.
Thanks, Avik. This concludes the formal part of the presentation. Operator, you can now begin the Q&A portion of the meeting.
Thank you. As a reminder, to ask a question, please press star one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one one again. Please stand by while we compile our Q&A roster. Our first question is going to come from the line of Julian Doolan Smith with Jefferies . Your line is open. Please go ahead.
Hi, this is Tanner on for Julian. Good morning and congratulations, Sandra. I just wanted to ask on the AESO large load Phase II. It's obviously in the pre-engagement phase. I just wanted to check in on your updated expectations for process, for ultimately what could be the scope and how you're viewing how you're level setting expectations going into the engagement phase beginning later this year.
Thanks for the question. As we've said before, firstly, we're excited about Phase I and potential parties coming into the province and really kickstarting the data center business. For Phase II, we are going to be engaged. We think we're well- positioned for Phase II given the excess capacity that we have at Genesee and we're overall constructive. As we said last quarter, we think the option value of our site at Genesee, combined with the excess load that we have at Genesee, positions us very well for that phase. Also, just as importantly, for anyone that's coming in through Phase I, we believe we're best positioned to provide VPPAs for it. I would say initial indications on Phase I are positive, which lends us to be more positive on Phase II. At the end of the day, this is an infrastructure play.
Our positioning of having generation in place that we're in the process of unlocking, in addition to the attractiveness of our site, ultimately, we think that positions us well.
Great, thanks. Maybe here we can dive a little deeper into the discussion around MSSC mentioned in the quarterly report. Obviously, this proposed reform has come up before and absent a technical solution, which I know you're exploring with AESO, it seems as though AESO kind of needs a philosophical change in its view of system risk due to singular unexpected failure or outage. Just perspectively, what are some signposts that we can look forward to indicate progress in these discussions or perhaps an evolution in AESO's thinking? Should we still view long-term resolution of this issue as directly tied to FFR or FNDR process outcomes?
It's a great question. Look, I think the AESO has been very constructive in their perspective on the MSCC. The MSCC limit to begin with was set for the G1 and G2 capacity originally. That 466 was the original capacity for G1 and G2. I think the leading indicator on their constructiveness is going to be through the two-way dialogue that we're having right now on the HPSO solution because that will, one, validate single nodal capacity over and above 466, although our solution ensures that we work within the existing MSCC limits. As we contemplate, this will be part of the Phase II conversation as well. I think overall, I think it's up to us to demonstrate the technical viability of our solution, which we feel very good about.
As you would have seen in the AESO disclosures, we've gone through preliminary testing already, and the AESO has been very constructive in working with us as we work to really cement the viability of one R option. Secondly, for the broader market, address the limit of 466 and potential increase of it. I can't say much more than that, but I think the biggest indicator is going to be how we perform on validating our own HPSO.
Great, thank you very much.
Thank you. One moment for our next question. Our next question will come from the line of Patrick Kenny with NB F. Your line is open. Please go ahead.
Thank you. Good morning. I guess starting with the co-location opportunity at MCV, just wondering if you could provide a bit more color on the potential timing for finalizing the PPA there and when the customer could potentially be online. Also, if you could just remind us what the ultimate brownfield potential might look like for the site itself and if you're able to scale this opportunity or perhaps bring in other data center customers over time as well.
Yeah, thanks for the question, Pat. As you know, the capacity at MCV is just over 1,600 MW. We've entered the long-term contract extension with CMS that speaks for 75% of that capacity. This 250-MW contract or LOI with the data center provider is a long-term contract in nature, but it does speak to 100% of the capacity at the site. We do see potential expansion opportunities in and around our plant at MCV. I can't speak to specifics around that. In addition, I would say our customer here has broader ambitions as well. I think part of the optionality of MCV site specifically is what's resonating. I can't speak specifically to how many megawatts or acreage are available and what that pathway is. What I would say is, although we haven't addressed pricing specifically yet on the contract, our outlook is quite constructive. Point one.
Point two, we're talking about long-term contracts that are, you can assume them to be well in excess of 10 years, closer to 15 years. We've got capacity and access to transmission distribution and potential upside in Michigan as well and at the site. I think as we've indicated, we've got a handful of sites that all have this capacity and potential, and we're actively working to monetize those available megawatts.
Okay, great. Thanks for that. On the PJM assets, I see both Hummel and Rolling Hills ran at higher capacity factors in the quarter relative to your base guidance. Just wondering if that was just seasonal strength through the summer or if you're now thinking this higher level of generation might be sustained going forward. If so, you know if you might be thinking about offering more capacity into the auction market this December from either facility.
Yeah, we're not in a position to comment on what our plans for the upcoming auction are. I would say early, in terms of this past quarter, you can presume it to be more around seasonality. We're overall constructive of what we're seeing at both of them. Generation and dispatch have been constructive. I think the outlook for the auctions is equally constructive. Early signs are positive for the quarter and what we've seen.
Okay. On the Arizona assets, if I could, just curious, on the back of the recent Transwestern pipeline announcement, I'm wondering if that's helped to spur any new commercial discussions with data center customers at either Arlington or Harquahala, or perhaps accelerate some recontracting discussions with the local utilities, just knowing that more gas supply is coming by the end of the decade to support the continued build-out of data center capacity across the state.
Yeah, look, in terms of affirming the long-term value of natural gas, I think this pipeline announcement is probably one of the biggest single data points for natural gas-fired generation in the U.S. in the last 5- 10 years. A major pipeline expansion, a $5 billion project, 42-inch line, only gets done with customers in place and off-take in place. In terms of our own position between Arlington and Harcahulla, we've had very constructive dialogue over the course of the last year and a half on whether it's upgrades, recontracting, potential growth opportunities, and those continue. I wouldn't say that they're better because of the announcement of the pipeline. The fact of the matter is we've been in those conversations over the last two years and been part of that overall dialogue affirming load growth in Arizona and the need for more gas to serve those load-serving entities.
I would say there's continuing interest in the market. I wouldn't say it's more because of the pipeline announcement, but I think our conversations and others have been a contributing factor to the pipeline and the firming of the outlook for the market in Arizona.
Okay, great. Thanks, Avik. Sandra, congrats on your upcoming retirement.
Thank you. One moment for our next question. Our next question comes from the line of Benjamin Pham with BMO. Your line is open. Please go ahead.
Hi, good morning. I also wanted to, first off, congratulate Sandra on her retirement as well. A couple of questions then on Alberta, if I can ask about that first. With your maintenance schedule that you have here into 2026, is that really positioning for a different maintenance schedule beyond 2026? Instead of every two-year cycle, you can just run the plants hard for four years to capitalize on the pricing situation?
No, Ben, it's not related to that at all. We did have scheduled maintenance planned for next year as normal course outages for those units. What we're actually doing is addressing a larger scope of work just based on some of the identified operational changes that we want to make through the early days of commissioning. They have identified incremental work that they want to do. As a result of that, because the joint ventures that we have in Alberta are also going through outage next year, it was going to be a really heavy outage year, which prompted us to move G3 forward into 2025. It is an increase next year relative to what you've seen the last few years where we've had relatively low planned outage days in Alberta as we went through the repowering of Genesee 1 and 2.
As we get through 2026 and 2027 and start to see prices go up, we'll be at a period of time where we'll be back to a more normal cadence of outages at that point. The scope of work, of course, will be dependent on run hours and what have you, but it's more just addressing some of those issues early on, which is consistent with our maintenance and operational practices. It's prudent that we address everything early on and be able to have the availability and reliability going forward so this doesn't create an incremental delay or push out further maintenance. It just gets us back onto a more normal schedule as we get through this initial period.
Okay, got it. Just give me your hedge position too on your deck in the back and at the 12 gigs for 2026. It doesn't look like just because you're shifting some maintenance around G3, Ford, it doesn't look like you're overhedged for 2026, just doing a quick high-level map on. Is that correct?
That's right. We would be basically flat next year, so baseload flat.
Okay. Maybe the last one, maybe some comments on the forward curve, a pretty big upward move there versus the beginning of the year. Can you talk about the trade and liquidity in those other years? Is that almost just Phase I being priced into the forward curve?
We did see a jump up after the announcement of Phase I in those later years. That definitely is a driver just as well as just normal course you expect as more supply gets absorbed in the market. You do start to see prices move up. A catalyst is definitely the Phase I announcement. As far as our hedge position in the liquidity, I would say we're more hedged than we maybe would have been when you're looking out through 2027 and 2028, just given some of the longer duration hedges that we have. The liquidity still is not as robust as you would see in the more near term. We're fairly significantly hedged in through 2027 and to a lesser extent when you get to 2028, where we're more modestly hedged.
Okay, that sounds good. Congrats again. Thank you.
Thank you.
Thank you. One moment as we move on to our next question. Our next question will come from the line of Maurice Choy with RBC Capital Markets. Your line is open. Please go ahead.
Thanks. Good morning, everyone. I just wanted to come back to your comments on Phase I of the AESO large load connection. Earlier, Avik, you mentioned that you could offer VPPAs as part of Phase I. We also know that a third-party developer has secured over 900 MW of the 1.2 GW of allocation. Can I first confirm if you still have your 375 MW allocation from Phase I? If not, what the big picture strategy here is for you?
Yes, Maurice. I can confirm that we don't have our $375 million. We made note of that at the last quarter. In terms of what may or may not be captured, I can't comment on that because it's not been announced or disclosed at AESO. I think we feel pretty good that there are going to be projects in Alberta. We also feel pretty good that, for anything that needs to have an in-service date in 2029 or earlier, we're going to be in a good position to provide them energy risk management or a PPA if and when they get announced.
Understood. I suppose just to follow up to that, what do you think still remains in terms of the milestones before that gets announced? Is it just government policy? Is it just crossing the T's and dotting the I's? How close are we to that and to your VPPA?
It's not our project, so I can't comment on where another project may be in the queue and their own negotiations. I can say, by virtue of our position in the market and our own decision-making around the $375, we understand that there are multiple projects in play that are advancing in the queue and will likely come out of the Phase I process. What I would go back to on this, Maurice, is the decision on the $375 for us versus maintaining option value on the $1,000. It's really about our whole business plan and focusing on long-term contractedness and optimizing the value per megawatt at our plants and PV per KW and long-term pricing. We do have a strong bias in Canada in particular towards these larger projects because we think they're more likely to yield long-term contracts. That's not the case in the U.S.
because of how mature the market is there and how much capital and how many players are chasing capacity in that market. Where Alberta is a new and emerging data center market, we continue to favor scale because of the likelihood of converting that into long-term PPAs.
Understood. Maybe just to finish up on that same theme, there's obviously been a lot of discussion about potentially introducing nuclear energy in Alberta. I know that we've talked about this before, but I recognize that it's very early days. From Capital Power's perspective, what do you see your role being and what are the conditions that you need to see before potentially investing in this technology in the province?
I think if we put technology aside, you know, specific SMR technology, and just look through it the lens of is nuclear viable in Alberta? We've engaged in this. We've got a best-in-class partner with OPG, and the province and the federal government have been supportive of us looking at the viability of nuclear in Alberta. The province has been very clear in its interest to determine the viability of nuclear in Alberta. We're still in that early phase of A, consultation, B, validating the technology, and C, understanding how nuclear would work within the existing framework, the electricity framework for the province. We do think that there is ultimately a role for nuclear, but we don't yet have the validation for, you know, how we would contract those assets in the existing energy-only market. You can't get ahead of, we can't get ahead of ourselves through the process.
This would be a long-term commitment. We haven't had load like this. There's initial investment required to bring the industry to Alberta. The province has been to date that the existing market structure will continue, and you have to find commercial ways to bring in load. Where these projects are longer duration, highly capital-intensive, you know, today they are not economic to do or to FID or spend material capital on. As we look out, our role is to, you know, manage that load growth over 10, 20, 30 years from a system planning perspective and understand that technology and understand, you know, when and if it's approved as a viable technology, how do we ultimately commercialize it? It's a long-winded answer to really say that today it's not economic. We're excited about it. We're exploring it with best-in-class experts. We're collaborating with government.
You know, we're keen to move to the next step. From a Capital Power perspective, in terms of capital allocation or putting risk capital towards it, it's not something we expect to do in the short to medium term unless there's something material that changes commercially.
Perfect. Thanks for the color and congrats to both Sandra and Scott. We'll catch up at Investor Day.
Thank you. One moment for our next question. Our next question comes from the line of John Mould with TD Cowen. Your line is open. Please go ahead.
Hi, thanks. Good morning, everybody. Starting off, I'd just like to pass on my congratulations to Sandra. Appreciate all your help over the years, and congrats to Scott as well. Going back to MCV, you've been able to both extend that contract and have this potential co-location piece for the merchant capacity. Looking across the rest of the U.S. fleet, are there other sites with similar characteristics where you can potentially do both? Is it really more a case of one or the other, you know, either extending your existing contracts or looking to do something on the co-location side? In those markets, how does the customer appetite for the co-location solution compare with the interest you saw in Michigan?
Thanks, John, for the question. We have multiple opportunities at multiple sites. I would say in the range of outcome, the things that we're focused on are upgrades, expansions, recontracting, and the data center opportunity. On our fleet, we have one or more of those opportunities on Hummel, Rolling Hills, Arlington, Park, La Paloma. I would highlight those as the ones that are most near term. What I would say, and this is something that we projected and advocated at our Investor Day in 2024, is we think that this is really about finding balanced energy solutions. What that really means today is you have to work with and cooperate and collaborate with load-serving entities, as we demonstrated at MCV.
For us, the way we're attacking this opportunity set is really talking to everybody and understanding how we balance the needs of our partners and fellow players in the market, load-serving entities, and what their objectives are with what our customers' objectives are, whether it's a data center provider or some other large load, and finding ways we can make win-win solutions, whether it's through upgrades, expansions, working with load-serving entities, and ultimately marrying those opportunities with our own, whether it's behind-the-fence co-location or grid-integrated, grid-connected opportunities. On the data center opportunity specifically, as I've said before, we don't believe there's a large opportunity to do these data centers behind the fence because of reliability requirements. You can do it, but the cost of generation to support f ive-nines reliability will greatly exceed the economics of the price per megawatt to make that work.
We think being able to grid connect is a significant advantage. Being able to work with stakeholders in those markets will be critical to successful outcomes. It's once again why we're bullish on the Alberta opportunity set because there is transmission distribution. Whether our role is to sell power and/or provide a site that we can sell, this is what we've seen and learned in the U.S. market, and that's what we've been leveraging in our approach in Alberta.
Okay, great. Thanks for all that color. Maybe pivoting to that Alberta opportunity, just in terms of an early look on the Phase II pre-engagement, it seems like putting your own power requirements is going to be likely in some fashion for Phase II. To reach that gigawatt scale opportunity, if you did host something in Genesee, would you need to add new build there? I note that in addition to the spare capacity you've got at Genesee 1 and 2, you do have a 1.5 GW early stage combined cycle project there in the connection list. How are you thinking about that? How do you think about the relative attractiveness of deploying capital into potential new build in Alberta versus additional gas and M&A in the U.S.?
Yeah, great question. One, we're not contemplating new build in Alberta as part of our entry into that Phase II. Second, we could contemplate it if there was a customer for it, but you need to look at the life of these assets versus contracting terms. We would not take merchant exposure on new build in Alberta. Third, relative to the U.S. or Alberta, I think whether it's, and I'll focus more on expansion and repowering than a straight new build because I think it will be unlikely we will take on a new build unless we've got strong partners and a strong off-take agreement. Those opportunities seem more prevalent in the U.S. today than they are in Canada.
I think from the expansion and repowering perspective, we see those as better near-term opportunities because you've got a better line of sight of having an in-service date that meets the needs of the customers. As we think about new build capacity in Alberta, the trick becomes how do you look at a new build and have an in-service date that meets the needs of the customer? That's why we feel so strongly about our position in the market. We've already paid for completed new build capacity through our repowering project in Alberta that's available now, and we think that positions us very well relative to the market. I think the new build piece or construction exposure or development capital exposure, we have a bias to the U.S. market today.
Okay, thanks for that. I'll leave it there. Thanks for taking my questions.
Thank you. One moment for our next question. Our next question will come from the line of Robert Hope with Scotiabank. Your line is open. Please go ahead.
Morning, everyone. My congrats as well to Sandra and Scott. Maybe carrying on the conversation on Phase II, has there been any changes to the customers that you're speaking to there or the level of support that you're seeing for your kind of next phase of projects for Phase II?
No, I can't say we've seen a different tone or different conversations or more conversations. The interest has been there for Alberta. Now that we have the guardrails for Phase I and Phase II, there continues to be interest. I expect when we get better visibility on what came out of Phase I, I expect to see more interest, in particular around larger customers. I would say we haven't seen more interest or less. It's continued to be the same.
Okay. Appreciate that. Just as a follow-up on that, the Phase II process, as was outlined by the AESO, is quite long. When you think about your positioning and the fact that you have 450 MW at Genesee that are unused right now, is there a way to potentially fast-track that process? Are you in consultation with the government or the AESO because your situation is a bit different than a pure bring-your-own-power solution?
I think overall, the AESO and the ministries have been constructive on how to go into Phase II. I think there will be some bespoke conversations with parties. I think our focus right now is very clearly in getting our technical solution approved, which will unlock us to 566. Over and above that, we've got additional capacity available. For us, the sequencing, which is independent of the Phase II process, is let's get our technical solution validated. Let's get the AESO on board with our solution and get those volumes unlocked. I think we'll have constructive conversations in Phase II. Most importantly, Rob, as you look at our portfolio, the way we look at it is whether it's through Phase II or Phase I, and you look at the strip in Alberta on pool price, our job is to go maximize value per megawatt on our plants and our dispatch.
Whether we're in Phase I or Phase II is less important than what's the probability we can go contract pricing, contract volumes at attractive pricing, short, medium, and long- term. We feel really good about that opportunity set right now. The longer Phase II takes and the more volumes that get taken up in Phase I and the more interest there is in the market, I think the better liquidity we'll see in the back end of the curve and the more opportunities there will be for us to go contract, which is how we're looking at the opportunity set.
We will continue to have this option on Genesee because I firmly believe our site is one of the most attractive sites on the continent for a large data center because of our access to fiber, because of our access to water, because of our interconnect, and because of the topography and location where we are at Genesee outside Edmonton. All those things are positive for the market overall. Most importantly, we feel strongly we're best positioned to sell power into this tightening market over the short to medium term. The outlook for Alberta is quite good right now as we look out from a tightening of the market and a pricing perspective and the limited number of generators there are and capacity there is.
Being at the right end of the merit curve here with the lowest heat rate plant, most efficient plant in the country, and the largest plant providing net power net to grid, we think that we're pretty well- positioned.
That's great. Thank you.
Thank you. As a reminder, if you would like to ask a question, please press star one one on your telephone. Our next question will come from the line of Mark Jarvi with CIBC. Your line is open. Please go ahead.
Yeah, thanks, everyone. Congrats, Scott and Sandra, and thanks for all the time over the last couple of years, Sandra. It's been great to work with you. Just on Midland and the data center customer, can you talk about any regulatory approvals, the contract structure, what has to get done there? I think Pat asked a question of like when the load could ramp. If you could maybe just share some color in terms of when this could move forward.
Yeah, thanks for the question, Mark. Yes, there will be some regulatory procedural approvals required. We're not in a position to say when an in-service date would be for this project. We do think that over the next 6 to 12 months, we can firm up the opportunity and the contract in partnership with our customer here. I can't give you more color than that right now. You can assume that the in-service date, given the fact that we have existing power, given that we have existing capacity, is short to medium term, not long term.
Understood. Coming back to the concept of the Phase I monetization and VPPA, relative to when you brought up this concept on the Q2 call to now, how would you say confidence level is? Is it higher today than three months ago?
On the concept itself of us being able to sell power into this market, the confidence is the same because we had high confidence in Q2 on it as we work through it. I don't think our confidence could be higher than it was then. It's the same in our ability to price power into this market. I think the only thing that's probably the market has more exposure to is there's rumor to be projects that are coming online. We're excited to see which projects actually come through and get announced and how we can support their build.
Understood. It does seem like you think, obviously, the megawatts that can't dispatch right now at Genesee could be counted as new megawatts for Phase II. you didn't seem too keen on building new generation unless you had a long-term contract. What about other technologies, battery, any solar? Would you look to maybe power any data center site at Genesee through virtual VPAs with other developers providing gas?
You mean others building gas on our site?
No, but more like a VPPA where they might build it or refurbish existing assets. Part of the solution for the data center at Genesee might be some generation either co-located or adjacent, plus some power through VPPAs.
Yep. I mean, we're totally open-minded on that front. I think that's really been our point all along, which is I think we're one of the best, if not the best, in finding creative solutions to contracting power for customers, whether it's bespoke or whether it's in partnership with others. To answer your question of would we be open to other investments at our site, solar, no. Batteries, maybe. Again, it's really going to come down to contractedness and terms, and can we make our cost of capital? I think the growing opportunity, and I think this is a point I've made previously, our job in this market, whether it's us or any of our competitors, as an industry, our goal is to sell more power and bring in more demand. I think as an industry, we're doing a good job of that.
On a relative basis, I think we're exceptionally well-positioned to sell that power given our fleet. On Genesee, I think we're open-minded. I'm not opposed to building, but today, I don't see a long-term PPA to substantiate that investment. If and when that comes at us, we'll look at it. We'll pursue it. I think Phase II, we'll see what other customers come to the table. Overall, I feel pretty good. I can't remember who asked the question, but in terms of the outlook on pool prices and the more bullish curve that we have into 2027, 2028, yes, there was an upward movement post-June, around the announcement of Phase I, but that was more than four months ago. That firming of that price scenario in 2027, 2028, I think just more broadly speaks to the market's confidence that there will be growing demand in Alberta.
I think it's just a timing question now. Do we see much of that load in 2027, 2028, or 2029? Overall, the support for higher prices and tightening supply, I think, is pretty favorable for Alberta.
Understood. Makes sense. You identified some sites in the U.S. with multiple options. I think Arlington Valley, Harquahala, Rolling Hills, Hummel. Are any of those sites gas-constrained if you do try to do upgrades or expansions?
I can't make a blanket answer on that because each site is different. For example, we aren't constrained. As I said, when we acquired Rolling Hills, we have available capacity at Rolling Hills, but we do not at Hummel. We do think we have upgrade opportunities at a couple of our plants in WEC. We don't see viability for a data center or a co-location of a data center upfront. I think the way I look at our portfolio today is we've got, call it, 2.6 gigawatts of contracted capacity in the U.S. that expire between 2029 and 2032, and we've got just over a couple gigawatts of fully merchant capacity in the U.S. We're trying to find ways to optimize that and increase it. It's a site-by-site response.
As I said earlier in the call, at those sites that I pointed out, there's one or more of those opportunities at each one of those sites.
Got it. All right, looking forward to connecting in a couple of weeks.
Thank you. I'm showing no further questions at this time. I would like to hand the conference back over to Roy Arthur for closing remarks.
Thank you, everyone, for joining us today. We appreciate your continued interest and support in the Capital Power story. We will conclude the call now. Thank you.
This concludes today's conference call. Thank you for participating, and you may now disconnect. Everyone, have a great day.